Good day, ladies and gentlemen and thank you for standing by. Welcome to EnCana Corporation's fourth quarter and year end 2009 results conference call. As a reminder, today's call is being recorded. At this time, all participants are in a listen-only mode. Following the presentation, we will conduct a question-and-answer session. (Operator instructions) Please be advised that this conference call cannot be recorded or broadcast without the express consent of the EnCana Corporation.

I would now like to turn the conference call over to Mr. Ryder McRitchie, Vice President of Investor Relations. Please go ahead, Mr. McRitchie.

Ryder McRitchie

Thank you, operator and welcome everyone to our discussion of EnCana's fourth quarter and year-end 2009 results. Before we get started, I must refer you to the advisory on forward-looking statements contained in the news release as well as the advisory on page one of EnCana's annual information form dated February 20, 2009, the latter of which is available on SEDAR. I'd like to draw your attention in particular to the material factors and assumptions in those advisories.

In addition, I want to remind everyone that EnCana reports its financial results in U.S. dollars and operating results according to U.S. protocols, which means that production volumes and reserve amounts are reported on an after royalties basis. Accordingly, any reference to dollars, reserves or production information in this call will be in U.S. dollars and U.S. protocols unless otherwise noted.

To provide a clear understanding of the new post-split EnCana, fourth quarter and full-year 2009 financial and operating results in this conference call highlighting EnCana's results on a pro forma basis, which reflect the company as if the split transaction had been completed as of January 1st, 2008.

In this pro forma presentation, the results associated with the assets and operations transferred to Synovus Energy are eliminated from our EnCana consolidated results and adjustments specific to the split transaction are removed. Financial information that reconciles EnCana's consolidated financial statement and pro forma financial statement can be found in EnCana's news release dated February 11th, 2010, available on our website. Also available on our website is our 2010 updated guidance.

Randy Eresman will start off with highlights of our operating results and reserve information and then turn the call over to Sherri Brillon, EnCana's CFO and to discuss EnCana's financial performance. Following closing comments from Randy, our leadership team will then be available for questions.

Before I turn the call over to Randy, I would like to ensure you're all aware of our upcoming Investor Day event scheduled for Tuesday, March 16th in Calgary and Thursday, March 18th in New York. The event will feature a series of presentations highlighting our asset base. Both days will be webcast and presentations available on our website. If you haven't already done so or received an invitation – haven't already received an invitation and would like to attend, please contact our Investor Relations team.

I will now turn the call over to Randy Eresman, EnCana's President and CEO.

Randy Eresman

Thank you, Ryder and thank you everyone for joining us today. This conference call is the first time I've had a chance to speak with many of you since we completed the reorganization of the company on November 30th of last year. I'd like to thank you for your overwhelming support of the split transaction and your continued support of our strategy.

I'm very pleased now to talk with you today about our peer play natural gas company. We believe new EnCana has positioned extremely well operationally and financially to choose strong future growth.

First, I'd like to highlight our performance in 2009, a year of challenges and a year of change. And also a very successful year for EnCana and a year that I believe underscores the strength and sustainability of our business model and the capability of our teams to respond to the changing environment and changing operational priorities.

The biggest issue that impacted the entire natural gas industry was the lowest average commodity price in seven years. However, our long-standing approach to risk management served us well, stabilizing our financial performance for the year. In addition, we responded prudently by shutting in or curtailing some of our productions to the lowest point in the price cycle helping to preserve value for our shareholders

Another change unique to our company was, of course, the reorganization of EnCana. Through this busy and demanding process, EnCana employees worked very diligently to make the transaction as smooth as possible and I would like to thank them for their great efforts.

Despite the potential distraction and transformation of this magnitude may create, our teams stayed focused on managing their respected businesses in delivering strong operational and financial results. Across our portfolio, we continue to see superior operational performance from our key resource plays. We lowered our operating cost and achievable strong improving capital efficiencies.

Pre-unit operating cost reductions are even more impressive when you consider the capacity of reduction we chose to implement for most of the year. For the year, we curtailed or shut in an average of about 300 million cubic feet per day of natural gas production in the areas where operational and contractual flexibility existed. Most of these volumes were brought back on during November and December with the remainder expected to come back on in the first quarter of this year.

Despite the self imposed reduction in volumes and the sale of assets producing 2% of daily production, total natural gas production averaged 2.84 billion cubic feet per day. We exited January 2010 producing about 3.1 billion cubic feet per day and we estimated that we still had about 125 million cubic feet per day shut in at that time, primarily in Canada.

Next, I would like to discuss the company's three emerging natural gas resource plays that we believe will be the drivers of growth for EnCana in the upcoming years, the Montney, Horn River and Haynesville plays. Within Cutbank Ridge resource play, we continue our steady development of the Montney formation where drilling completion an timing costs for our current wells are now about $5.8 million, down 11% from a year ago despite an increase in the average number of fracs per well going from 8 to 9.

Our most recent wells are being drilled with horizontal length of approximately 8,000 feet with 14 fracs stages. With tremendous development opportunities in this key resource play, approximately 2,500 future drilling locations identified.

In our emerging Horn River play, our 2009 program focused on drilling efficiencies, testing the potential of evolving drilling technology and leveraging economies of scale. We've had very strong well results for our recent 12 and 14-stage fracs achieving initial 30 day production rates of 8 to 10 million cubic feet per day.

Our most recent wells have been drilled with horizontal lengths of about 7,500 feet and have an average of 20 frac stages. We're targeting drilling, completion and tie-in costs of about 500 to $600,000 per completed interval or a total cost of about 10 to $12 million per well.

Over the last year, cost on a per frac interval dropped by about 25% through combination of improvements in technology, economies of scale and cost deflation. We expect that our Horn River program in 2010 will be more balanced with continuous drilling and completions program occurring throughout the year. We have about 800 fracture stimulation jobs planned in 2010.

We've now received an environmental assessment certificate from the B.C. Ministry of Environment for the EnCana-led Cabin Gas Plant Project. Additional approvals from B.C. Oil and Gas Commission are still required. Subject to those reviews, which we expect to be completed this spring, we anticipate having the first stage of 400 million cubic feet per day for treating capacity on stream by September of 2012 with the potential expansion of up to 800 million cubic feet per day in the future.

Canada has an interest in the plant and we are the operator. In the Haynesville play in Louisiana, we continue to have great results like the Horn River, we have a very large position in this play and our results continue to be strong with continually improving well performance.

We exited the year producing approximately 125 million cubic feet per day in Neptune EnCana from 33 wells. Currently producing about 180 million cubic feet per day from a total of 39 wells. Drilling, completion and time costs were down 40%.compared to the fourth quarter of 2008 or targeting total well costs of about $9 million per well in 2010.

Our primary focus in the Haynesville this year continues to be on land retention and completion optimization. We're executing program through 2010 and 2011 to ensure we obtained our most respected lands, expect to drill at least a 100 wells this year and have a target exit rate in excess of 400 million cubic feet per day. The latest '10 wells have averaged approximately 20 million cubic feet per day, flowing at around 85,000 psi.

There's also the potential for additional upside across a large portion of our land position. In the mid Boulder Zone, we've recently completed two wells that are showing excellent results. One of the wells located in the Red River Parish floated about 19 million cubic feet per day at more than 8,500 psi flowing case and pressure during initial test.

Although there's still a lot to learn, Haynesville play has the potential to become the leading resource play in California. Expected growth in 2010 will be driven by our U.S. division and Haynes will be a key contributor to that growth.

Virtually all of Canada's major resource plays benefiting from the same technology enhancements which extend the horizontal reach of our wells and increase the number of fast stimulations and treatments we perform. As this occurs, we're continually improving our operating efficiencies and well performance, driving down costs on a per-unit basis, which reduces our supply costs and helps to maintain strong margins despite lower than expected long-term natural gas prices.

This gas factory approach is a strategy we employ for all of our resource plays, one which over time will allow us to maintain our position as one of the lowest-cost producers.

Now, to year end reserves. We're pleased with our reserve additions in 2009 despite a significant and constraint drilling program during the year. The team's efforts resulted in reserve additions with four SEC price divisions excluding acquisitions and divestitures of approximately 1.9 trillion feet of gas equivalents. This was achieved with associated capital investments of about $3 billion.

Approved reserves before price divisions increased about 3% to 12.8 trillion feet of gas equivalent. Before acquisitions and divestitures, we replaced 169% of the company's 2009 pro forma production and our reserve life index remains at about 12 years.

Resulting natural gas planning and development cost of $62 per 1000 cubic feet equivalent per on time on an organic basis represents a decrease of approximately 25% from 2008. And by organic, we mean excluding expenditures associated with central processing and gas guzzling facilities and undeveloped land, a methodology that we believe is more consistent with our new competitor group.

In similar fashion, Canada's pro forma three-year average natural gas planning and development cost is about $1.92 per 1000 feet cubic feet equivalent. Expect to see a downward trend in F and D costs over the next couple of years as we continue to improve our cost structures and focus our operations on the lowest cost plays.

Our reserves continue to be 100% externally evaluated by independent qualified reserve evaluator, not just reserved or audited. Additions before both price revisions and acquisitions and divestitures were led by Haynesville with about 660 billion cubic feet equivalent. Jonah added about 400 Bcfe, Cutbank Ridge approximately 285 Bcfe, Greater Sierra about 195 Bcfe and Bighorn approximately 175 billion cubic feet equivalent.

At year end, we also recorded downward adjustments of about 400 billion feet equivalent associated with our Canadian Horseshoe Canyon EnCana Corbett mapping operations. This was partly due to a small performance adjustment to a very large number of wells and partly due to increasing shrinkage back, is also partly due to a line of PUD inventory to match the slower drilling program.

Overall, it is a relatively small reduction of our CBM reserves in an area where we expect to book several trillion cubic feet of gas in the future. Overall, capital spending reductions significantly exceeded our expectations for the year. In spite of activity levels largely matching our original plans, we finished the year below our CapEx guidance. This was primarily accomplished through our operating and corporate team's focus on delivering too and exceeding the internal 10% cost reduction challenge.

Our teams went beyond our expectations achieving actual savings of more than 20% on a pro forma capital, operating and G&A spend. These savings allowed us to allocate additional capital to other areas in the company such as our land retention program in the Haynesville Shale and land captured and a potential new play in Western Canada.

In addition, we completed a number of planned divestitures in the last half of 2009 as planned. For the year, net divestitures totaled about $800 million. We continue to look at other opportunities to highlight our portfolio and I've already completed about 130 million in divestitures so far this year. Additional sales are not critical to our 2010 capital program and we do not intend to sell assets at prices below our value.

In summary for 2009, EnCana managed through the most significant global economic crisis in our history, achieving outstanding operational and financial results. We delivered on the goals we set for ourselves and promised to our shareholders, meeting or exceeding all of our guidance estimates. As a result of the split transaction, EnCana has a very robust base of operating assets and a very solid financial position that together with our teams provide a foundation for significant future growth potential.

Looking forward into 2010, we initially set EnCana's capital budget at 3.6 to $3.9 billion. At this level of spending, we expect to achieve production of 3.2 to 3.3 billion cubic feet equivalent per day. In the process of valuing our pace of development considering our huge portfolio of low cost opportunities and expect to provide an update to our forecast and more details of our portfolio at our planned Investor Days in mid-March.

I'll now turn the call over to Sherri Brillon, who will discuss our overall financial performance.

Sherri Brillon

Thanks, Randy. As Randy pointed out, despite a challenging economic environment, EnCana continued to demonstrate capital discipline and financial strength. This is reflected in both our year end results and our current financial positions.

Realized after-tax hedging gains of approximately $2.3 billion or about $3.15 per thousand cubic feet equivalent, provided stability to our cash flow through the year.

Our pro forma cash flow of $5 billion is aligned with our November 12, 2009 guidance of $4.2 billion. Once the tax associated with the windup of our Canadian oil and gas partnership and transaction costs are adjust, for as previously noted in our guidance.

Our strong cash flow performance was accompanied by strong pro forma operating earnings of approximately $1.8 billion, or $2.35 per share on a diluted basis. These earnings figures were again, supported by our risk management program.

Looking forward, as of January 31, 2010, we have approximately 60% or about 2 billion cubic feet per day of our expected 2010 natural gas production hedged, for the calendar year, with fixed price instruments at an average of $6.4 per thousand cubic feet.

In addition, we currently have fixed price swaps on about 935 billion cubic feet per day, for 2011 and about 870 million cubic feet per day for 2012, both at an average price of about 650.

As we witnessed in 2009, having hedges in place help provide protection on the downside, creating increased certainty for our cash flow, capital program and dividend. Our hedging arrangements are with a diversified group of approximately 20 different counter parties with strong investment grade credit ratings.

Despite the commodity price volatility and recessionary pressures, our balance sheet remains strong and we continue to employ a conservative capital structure. Our total debt at year end 2009 was $7.8 billion, down from 1.2 billion a year ago.

Debt to adjusted EBITDA calculated on a pro forma basis, finished the year at 2.1 times and debt to capitalization at December 31, was 32%, despite having $2.6 billion in cash on hand, net of our current tax obligations.

Net of working capital, these ratios would be 1.6 times and 27% respectively. Therefore, we are financially well positioned to pursue our operating plans this year and look at potential additional opportunities for investment as they arrive.

We also have available unused committed bank credit facilities of about $4.9 billion. In the next two years, we have one U.S. dollar debt maturity of 200 million in September of 2010 and one U.S. dollar debt maturity at 500 million in November of 2011.

Now looking specifically at our costs for the year. Combined pro forma operating administrative costs were $1.11 per thousand cubic feet equivalent and below our guidance expectations by about 3%. Costs decreased by about 14%, compared to last year primarily due the widespread impact of a 10% cost challenge, increased efficiencies and renegotiation of supply and service agreement.

With respect to inflation, cost pressures eased throughout 2009. Overall deflation for the year was in line with out 0-5% expectation.

For 2010, we are expecting inflationary pressures to remain relatively flat with some exceptions in specific areas of heightened activity. Wherever we can, we are working towards achieving longer term contracts for goods and services.

Our currently quarterly dividend of $0.20 per share represents a current yield of about 2.5% on an annualized basis. This is slightly above our target range 1 to 2%, but we are comfortable with the annual $600 million capital commitment that our current dividend represents.

The quarterly dividend remains at the discretion of the board, but there are no plans to change it at this time. Overall strong financial results were in EnCana. We are well positioned for continued financial flexibility and discipline capital investment.

I will now turn the call back to Randy.

Randy Eresman

Thank you, Sherry. EnCana continues to demonstrate what we believe to be industry leading performance from the developments of unconventional natural gas resource plays.

Our portfolio was strong in assets, supported but solid financials is a direct result of our focused strategy. We've been building our North American portfolio, fine-tuning our approach to resource developments and establishing strength and flexibility in our balance sheet for years and that discipline is paying off now more than ever.

Overall our 2009 results are very positive and indicative of the strength of our company. Like any year, 2009 had its challenges and its triumphs. But our strategy appearing low-risk, low-cost North American resource plays with a strong balance sheet and favorable commodity price hedges, has allowed us to be resilient to the lowest part of the commodity price cycle and maintain our position of strength.

As we move forward in 2010 and beyond, we believe that North American natural gas prices will be, on average, lower than what we've seen historically. Our operating practices, leading technologies and increased efficiencies position us very well to continue to capture strong margins and strive in a competitive price environment.

Sherri pointed out earlier we have a strong balance sheet and are extremely well positioned to financially to capitalize on potential investment opportunities that may arise.

Risk management program aims to underpin our capital and operating programs and we are maintaining our focus on applying advanced technology to increased operational efficiencies across the company.

Our 2009 performance demonstrated that even through a significant economic downturn, our ability to create shareholder value was sustained. We're well positioned for the future with an asset base capable of delivering double-digit growth for the long-term, while at the same time working to further reduce our cost structures and improve operating efficiencies.

As I mentioned earlier, we will provide more detail on our entire as it base as well as an update on our capital programs at our March investor days.

In addition Eric Marsh, Executive Vice President of the natural gas economy will give a presentation on our efforts to extend natural gas demand in North America. It's clear that natural gas had an important and expanded role to play in the future energy supply for the continent. Addressing both energy security and growing environmental mandates.

Based on the estimates recently provided by the U.S. Department of Energy, natural gas reserves are capable of supplying North America's current demand for over 90 years.

Recognizing that North American natural gas is now likely to be more abundant and more affordable, there's an opportunity for natural gas to displace even more coal and imported oil and effort to become a much larger source of energy for power generation and for transportation fuel.

A secure, affordable domestic energy supply is only one case for extended natural gas use. It is also the cleanest burning fuel emitting 30 to 40% carbon dioxide than oil and coal. Burning natural gas emits virtually no for sulfur dioxide, which is a major contributor to smog. So, significant reductions in emissions can be achieved by broadly switching to natural gas as a fuel source.

There's been a paradigm change in the supply and affordability of North American natural gas, exciting opportunities and changes lie ahead and EnCana is ready to play a leading role.

Thank you for joining us today. Our teams are now ready to take your questions.

Question-and-Answer Session

Operator

(Operator instructions) Your first question comes from the line of Greg Pardy from RBC Capital Markets. Your line is open.

Greg Pardy – RBC Capital Markets

Thanks. Good afternoon. Randy, you're sending some loud messages. I mean, certainly in terms of gassage is owed in 2012 and you've alluded to it, but what is your thought process there and why you hedge out this far if there is the potential for just a recovery on the industrial demand side?

Randy Eresman

Thanks, Greg for the question. We do an evaluation of North America's natural gas supply and on the conclusion of that analysis we believe that there is considerable amount of domestic gas plays, particularly in the shale plays, but also other plays that benefit from the technology.

Greg Pardy – RBC Capital Markets

Randy, you're a little hard to hear.

Randy Eresman

You know what? I didn't have my Mike on. I apologize for that.

Greg Pardy – RBC Capital Markets

No problem.

Randy Eresman

What I was saying is that – EnCana does and has for a number of years done a fairly exhausted evaluations of the fundamentals of North American natural gas supply and it's our view that the efficiencies created by horizontal drilling and mass hydraulic fracturing stimulations of wells and shale plays and others that benefit from that technology, that we are seeing that the supply can meet demand at a much lower price than historical and I guess our view is that natural gas price is at a lower level in and historical expectations are here to stay.

And so the companies that can do best in that environment are the ones that can operate in plays and create the – and have the lowest overall supply cost and we believe that, despite the fact that we expect natural gas prices will not likely rise to historic levels, we will still be able to develop very good margins in that environment.

Greg Pardy – RBC Capital Markets

Are you changing your mid-cycle pricing expectations?

Randy Eresman

With every new piece of information we receive, we're more confident and the ability to continually lower supply costs. The only – the wildcard in all of this, this inflation at some point kick in. So, when I reference the lower supply cost, I'm really talking about in reference to today's cost structures. But efficiencies are continually improving in all of our plays, to the extent we could have never imagined a few years ago.

Greg Pardy – RBC Capital Markets

And just point of reference, 650 was your last, is the price you run with now, correct?

Randy Eresman

That was our most recent price tag, yeah. We ran 550 for 2010 and 650 beyond. So we're seeing some amount come off of that. I don't think we are going to be specific about it, but we are seeing it come down a bit.

Greg Pardy – RBC Capital Markets

Okay. And last one for me is more fully loaded F&D number that would include undeveloped land and gathering systems and so forth. That number may have been the release, but could you just mention what that would be as opposed to the $1.62 you quoted?

Randy Eresman

Bob. Do you have that number handy? I think it's around $1.80.

Bob Grant

A $1.98.

Randy Eresman

A $1.98.

Greg Pardy – RBC Capital Markets

Okay. Thanks very much.

Randy Eresman

You're welcome.

Operator

Your next question comes from the line of Chris Theal with Macquarie Securities. Your line is open.

Chris Theal – Macquarie Securities

Good morning. Can you hear me, okay?

Randy Eresman

Really good, Chris.

Chris Theal – Macquarie Securities

Okay. Just a question, Randy. With respect to new plays, can you comment, what's sort of common horizon with EnCana? Both in the U.S. and in Canada and I'm curious if you guys are looking at the Devonian Shale number and they have been planning in land sales at all there?

Randy Eresman

Okay. I'm not sure we are going to divulge too much on plays. We haven't talked about in the future at this point in time, but I think we can talk about exciting things that are happening on plays, you're probably aware of.

I'll let Mike talk first about Canadian plays and then Jeff will maybe talk a little bit, what we're doing in the U.S.

Chris Theal – Macquarie Securities

Thanks.

Mike Graham

Hi, Chris. Mike Graham here; I am with the Canadian division. Talking about the Devonian Shale number, we do think that the Devonian Shale can emerge as a big player numbered and you've recently seen on the land sale activity. So, I think it's sort of a vote of confidence for what Alberta is doing in their competitiveness review.

And we do attend a lot of land sales in DC and Alberta as well. So stay tuned for that. Just a little bit maybe in the Horn River, Chris, what we have. The horn river, like Randy said, we continue to drill our wells a bit longer. We're getting out to 2,200 meters now in the horizontal.

We're putting in more wells per pad, as many as 16 wells per pad and we're actually putting more fracs per well. The teams are looking at putting 22 fracs per well and about 200 tons per frac. And like Randy said, the results from our ten and 12 frac and 14 frac horizontals have been good, averaging 8 to 10 million cubic feet a day for the first month and we do think that our wells – with 22 fracs per well are going to be that much better again.

So, we only put on four wells for 2009 and we are doing these as a pad, if you will, so we're going to have a lot of production coming on for 2010. We're going to exit 2010, we think about a 100 million cubic feet a day net to EnCana with a couple of paths coming on through the year and, 2011, we think we'll exit at about 200 cubic million feet a day that to EnCana. So like Randy alluded to, we drilled the longer, put in more fracs and they continue to get better and we're excited to see that where the Horn River going. We think we have somewhere in a year above 50 TCF net original gas in places or land. It is a very, very big resource.

Chris, I could, may be just comment quickly on the as well and similar to the horn river, our guest Haynesville, we continue to drill the wells longer there. We recently drilled wells as much as 2,400 meters on the horizontal 14-stage frac and typically our average wells on 8 frac 1,000 meter well would come in, in the order of about 5 million cubic feet a day. These wells 2400 meter 14-stage frac are coming on in the order of our last wells there are 11 million, 13 million and 30 million cubic feet a day.

So we're exciting to see that. The cost on a per interval basis continues to come down. We think by drilling sort of six horizontals of a path in the Montney, our cost can hopefully get in close to that 500 to $600,000 per frac and we continue to recover probably about 0.5 to 0.8 BCF per frac. So we drilled about 50 net wells in the Montney last year and in 2010 we're going to drill somewhere in that order again. Only these wells will be longer with more frac. So we continue to like what we see in the Montney and in, in the Horn River and I think, I'll turn it over to Jeff to talk a little bit about Haynesville.

Jeff Wojahn

Thanks, Mike. And I'm going to talk about the Haynesville a little bit. And, Chris, when we talk about our land retention strategy in Haynesville, we talk about drilling 50 wells in 2009. An additional hundred net wells in 2010 and then finishing off that program in 2011 with an additional hundred wells, which by and large attacks about 165,000 net acres of our land position. Of course, our land position is 430,000 net acres. So we're really talking about attacking the areas where we have originally acquired our land in what we think is the core of the Haynesville trend and we're rally attacking just that area.

There's another area so called phase III area within the company that we'll be looking at in the 2010 and 2011 area that's another hundred thousand acres. So now just within that 165,000 acre area that we're currently planning and working on the expiring component of our land base, there's a tremendous amount of opportunity. In this current quarter, we announced a well that we've drilled in the mid Borger. We haven't focused a lot as an industry and a company on the mid Borger potential. But the impact to EnCana's resource potential is very significant.

Obviously, you've heard a lot about the Haynesville by itself is producing over 2 BCF a day. Canada for its part is currently producing 200 million cubic feet a day just from the Haynesville and just on wells that we're drilling on a per section basis. Nonetheless, they are still growing. The mid Borger has the capability of rivaling our Haynesville position in the play and certainly the results that we are getting, the more customarized completion programs associated with mid Borger are giving us new well results that are – that rival the Haynesville itself. So just in that sense we can – we can have thousands of wells that we potentially could drill in that 165,000 acres.

Beyond that, we can continue to work on 430,000 acres. So I hope that gives you a flavor of the immense potential that we have.

Chris Theal – Macquarie Securities

Jeff, how many horizontals are in the mid Borger now?

Jeff Wojahn

In the play?

Chris Theal – Macquarie Securities

Yeah.

Jeff Wojahn

In the mid Borger?

Chris Theal – Macquarie Securities

Yes.

Jeff Wojahn

We have three or four ourselves. I would say, as an industry, we have dozens but not many. Now, we also have a couple thousand industry verticals as well, that have targeted and test results. So it's really in its infancy compared to Haynesville. There's a number of reasons. First of all, the mid Borger potential seems to be more in a southern and central component of the play extent. It's not as prevalent or as prospective I should say. You know, a lot of the northern areas which have been developed earlier in the play history. But the mid Borger really has strong reservoir capability in the area where EnCana has its land base. And we haven't really gone after it so to speak because of the land retention; we need to drill through the deepest zone, which is the Haynesville and producing quantities. So it kind of goes a little bit against our land retention strategy to drill mid Borger. That doesn't mean we don't like it though and it doesn't mean that it doesn’t have the capabilities to drive in Haynesville, ultimately in our quarter end.

Chris Theal – Macquarie Securities

Thanks for those answers guys. But one more thing, if I can bug [ph] can you just walk through your additions by resource play one more time?

Jeff Wojahn

Addition by resource play?

Chris Theal – Macquarie Securities

Yeah.

Jeff Wojahn

Okay. For a second, all right. So we have booked about 600 BCF in Hendril [ph] Jonah we added another 400 BCF that was a largely due to down spacing to (inaudible) take a spacing to some parts to play, Cutbank Ridge, commodity that’s added 285 BCF. Greater Sierra area I guess 195 BCF and Bighorn depressant price 175 BCF and then now is offset by the CBM write-down nice spoke.

Chris Theal – Macquarie Securities

Thanks very much.

Randy Eresman

You're welcome. Thank you.

Operator

Your next question comes from the line of Brian Singer with Goldman Sachs. Your line is open.

Brian Singer – Goldman Sachs

Thanks. Good morning.

Randy Eresman

Good morning, Brian.

Brian Singer – Goldman Sachs

Following up on your comments on the mid Borger when you think about capital to commit, how many wells do you expect to grow on the mid Borger and of your acreage position in net? What do you think you will and that’s going to keeping over the next two years and what do you think you lend up is surrendering any?

Randy Eresman

Jeff, go ahead.

Jeff Wojahn

Good morning, Brian. With a big Borger, we probably want to drill, less than 10, 100 wells in our program for this year, specifically the mid Borger. Again, we want to – keep 165,000 net acre strategy in land attention in place. The answer to your question Brian is really a schedule advance in the next 2008, I'm sorry, 2009, 2010, 2011 period we really have expiries reason associated with the 165,000 net acre position, so go page three are you going to mentioned earlier of the 100,000 acres begin to expire 2011 but the leases and the terms of leases are more favorable for retention.

So we can do continues drilling operations that we choose but we are also can group leases together greater 640 acre basis.

So I think as we go down to time we are going to look at the information either from the industry hopefully the industry will prove up reminder of our land. And we are also looking at our own drilling results development strategy on potentially saving all over land. We haven’t condemned any of our 435,000 acres as being not commercial. We feel ultimately that we have straitening and that’s going to five year so now but before we kind of get there.

Brian Singer – Goldman Sachs

Thanks. And Randy can you give us, you saw to latest thoughts on Marcellus and whether you see EnCana taking a greater role?

Jeff Wojahn

With regard to Marcellus, we did do the small entry position and what we would like to do right now as make sure we understand the issues and I guess the profitability of the pipe report we decide whether not there is something in area that we could plan. But I guess the real answer is we weren’t there first and we would like to be person in that place and so we think they are maybe other opportunities where we can find just as good plays but from an exploratory stage.

Brian Singer – Goldman Sachs

Thanks. I can ask a one last little follow-up. You mentioned 8 to 10 million cubic feet per day, IPs and Horn River Basin and what your expectation for UR associated with those well?

Mike Graham

Yeah, Brian. Mike Graham here. We’d like to say it's very early in the Horn River, Haynesville, a lot of this emerging type share price but these are very encouraged. We think we may get as much as much as 0.8, even in the much 1 Bcf for frac on an yearly basis. So we may have well but that would be 10 to 15 Bcf see largely in the Horn River. I would like to say its early we don’t have log on for couple of years but that the clients terms are according to (inaudible)

Brian Singer – Goldman Sachs

Thank you.

Operator

Your next question comes from the line of Mark Gilman with Benchmark. Your line is open.

Mark Gilman – Benchmark

Guys, good morning. I wanted if you could both Jeff and Mike talk a little bit about the production numbers, both in the deep Borger, East Texas in the fourth quarter as well as Mike, I think, the Cutbank in the fourth quarter but volumes in both were really low and I was hoping you could relate that to Randy’s comment as to the areas of the Shut-ins and what particular place, where was production being most significantly impacted by the Shut-in. Also a comment as to whether the 125 the day indicated number as we speak includes or does not include differed completions and where we stand on that one? Thank guys.

Randy Eresman

Hey, Mark. Mike and Jeff just refreshing results of the numbers but the areas that you spoke of are the areas that we did target the Shut-in gas and most of that gas as we said was – we started to bring it back on screen as went ahead, price started to rise again.

Mark Gilman – Benchmark

Mike, how much gas did you slot Shut-in, I think, you said it was around 125 at the end of January but we started bringing back?

Mike Graham

Yeah. Well, we probably have about of that still shut-in really somewhere in that order. We think sort by the end of this month, we will have most of that back on target. But we did have, we head for trip contained a lot of volume. We drill a lot of well. We decided not to complete them so we are out there completing in off a lot of well in Cutbank as well and before never like to say we only put on four well in the board member last year. We drill like 20 net well in the Horn and we drilled another 20 net well. So we’re starting bring this big well pattern. We started very low production a day probably less than 20 million cubic feet a day, that kind of Horn River and I get to say we should access about 100 million cubic feet a day in the Horn River and for Cutbank Ridge and sort of a Q4. We did have some problems, we may have heard about that we have a gas leak up and round Dawson Creek and we decided to shut in and to some 190 well. So we actually took about 250 million cubic feet a day offline and then Q4 plus that curtailment if you will and like Randy said at the end of January had about 125 million cubic feet a day Shut-in. So we will bring that Shut-in volume back on over the next month and we are out there now and to a lot more completions that we did in 2009. So volume for a Canadian division will continue to ramp- up. We actually were very close to our budget in January which we’re excited to see and we are going to have good growth throughout the year. So we are very confident in our approach.

Mark Gilman – Benchmark

Okay.

Jeff Wojahn

Yeah. Good morning. Mark. In U.S. Division, our annual production for last year was just over 1 point Bcf a day and we have stated that we had about 200 million a day annualized Shut-in during the year. East Texas was one of those areas that we probably are in place. Current production is around 1.9 Bcf a day meaning that we are going to step it up and brought on most of our additions. So I am quite pleased on how the gas has been able to come back on right where we want to be, the specifics around East Texas, East Texas was where we chose to Shut-in our production. We have full year average production of 324 million and as we speak right now, our produces been over 450 million. So it gives you kind of flavor of how much we shut-in and how will bring it back? In the majority of the U.S., the division has all of its gas on?

Randy Eresman

Mark, I should also add that in before the quarter, we would have seen the sale of our (inaudible) asset show up as a reduction of about 60 million a day but we are also part of the impact on the quarter.

I wonder well, I had – I am a little bit surprised Randy given what you and your colleagues have said about your supply cost and may be Jeff can comment on this? About the size of the price related revision, the 9/14 number in the U.S. division, may be, give me a little bit of color Jeff on why that number is quite so large on the basis of – we have price on the 380 range.

Randy Eresman

380 is a pretty low price.

Mark Gilman – Benchmark

Yeah.

Jeff Wojahn

380 is not our expected business case. Randy talked about some of the pricing for but. It reflects some of the higher cost structures that we have in the Rockies versus the Piceance basin. But again, we don’t think 380 is really what we should measure our business case or expected values from and so that is why we have given you our best case.

Mark Gilman – Benchmark

Jeff, are these price related revisions? That 9/14 in the U.S. is that all the products?

Jeff Wojahn

Yes. Yeah. The short answer is yes.

Mark Gilman – Benchmark

Yeah.

Jeff Wojahn

We have been present in Canada as well.

Mark Gilman – Benchmark

Okay, guys. Thanks very much. I appreciate it.

Jeff Wojahn

Thank you.

Operator

Our next question comes from the line of Bob Morris with Citigroup. Your line is open.

Bob Morris – Citigroup

Thank you. Good afternoon. Following up on the reserve question, you noted here that pro forma percentage was 44% at the year in ‘09. I didn’t see a figure in there as to what that percentage cost pro forma at the end of ’08? Do you have that number?

Jeff Wojahn

Yeah. Just a second.

Randy Eresman

Yeah. That number was just above event. The number was 41% at the end of 2008 pro forma.

Bob Morris – Citigroup

Okay. Thank you. Second question, quick here. It looks like that apart from shut-in gas production was up at the end of January about $125 million a day, what I have averaged in the fourth quarter? Was that increase mostly in Haynesville. In other words, the increase separating at shut-in has come back on line. The increase in production at the end of January versus fourth quarter average.

Randy Eresman

Go ahead, Jeff.

Jeff Wojahn

Bob – Jeff Wojahn speaking. I think it’s more of a function of the flush production associated with bringing on the new production. Obviously, at Haynesville results are adding to that. It sounds about it was included in their budget as well.

Bob Morris – Citigroup

Okay. And then, last question, you mentioned that you’ve moved down your mid-cycle prices $6.50 and then now previously you mentioned that the chronicles is only economic above $6.50. What is that purchase in regard to that project now?

Jeff Wojahn

On a go-forward basis, the project is almost belted; it will be done by the end of this year. The economics are pretty good going forward and that’s really going, we have to think about it.

Bob Morris – Citigroup

Basically, on an incremental basis going forward with a prior cost just on …

Jeff Wojahn

On a full cycle basis, it’s pretty breakeven, I think.

Bob Morris – Citigroup

Okay. All right. Good. Thank you.

Operator

The next question comes from the line of Ray Deacon with Pritchard Capital. Your line is open.

Ray Deacon – Pritchard Capital

Yeah. Hi. I had a question mark regarding the number of frac stages on the middle Borger well that you put on and also in the your wells that averaged 20 million a day for an IP [ph] origin in Haynesville. How man frac stages are you doing on those?

Randy Eresman

Sure. Jeff will answer that.

Ray Deacon – Pritchard Capital

Thanks.

Jeff Wojahn

Good morning. Generally, we’re trying to drill as long as horizons began and stay within our six hori space and which means that by large during that foot range for horizontals and even most recently gravitated towards 14 stages about former line parallels per well for both the mid Borger and the Haynesville.

Ray Deacon – Pritchard Capital

Got it. Right. And also I just want to take a picture of question. When you show the slide of all the major producers and where are you rank there. It seems like a lot of those companies are now trying to grow production more aggressively than they have in the past and if you, kind of, listen to EOG yesterday, they still felt this though you’d see a maybe a two to four BCF decline in production versus thick level seen last year, I guess. What are you thinking at this point?

Jeff Wojahn

So you may be talking about in terms of market demand, North American demand. Well, so I mean, on the other side, in terms of supply, I guess, what would be your thought on 2010 versus 2009. I think, it will probably be very matched to the demand side. So I don’t think we are going to go much.

Ray Deacon – Pritchard Capital

Right. Okay. Got it. Do you have any kind of view on the headcount that would be required to maintain flat production, I guess.

Randy Eresman

We can give a pretty put some presentation at our Investor Day on March 16 in (inaudible) and 18th on New York. I think a lot of these more details are answers. We will be providing investors and analyst with tremendous amount of information at that time.

Ray Deacon – Pritchard Capital

All right. Thanks very much.

Operator

Your next question comes – we are now taking questions from the media. Your next question comes from the line of Amanda Fraser with AllNovaScotia.com. Your line is open.

Amanda Fraser – AllNovaScotia.com

Hi. I was just wondering what the impact of the midway in drilling will have on first half?

Randy Eresman

Mike Graham will answer that.

Mike Graham

Hi, Amanda. Mike Graham here. We were scheduled to bring different owner Sanchez [ph] in Q4 2010. The product feels senate and they will be dealt in Abu Dhabi and its getting out of Abu Dhabi, a little later or so. We actually slipped probably in Q1 2011 or Q2 2011 somewhere in that order. The delay of the rig getting out of the harbor as we had to wait for the right things to get the rigor on site. You know, Ray will set us back at where it is, more so on the production center. We were all in, we have drilled the first level of that program where we have reached TD on a disposal level and everything looks encouraging there and we are going to move on to a slowly completion after that.

Amanda Fraser – AllNovaScotia.com

Working over, in fact, on the project, is that, TFC being late.

Mike Graham

Well, you know the project is just a later quarter two side thing on that. So we still expected to come on, add about 200 million cubic feet a day and that we’re just acting accordingly and that’s really just a small delay in the project.

Amanda Fraser – AllNovaScotia.com

Okay. And what about in terms of the capital cost, it would have occurred with different estimate there?

Mike Graham

There has been – there has been a big creep on the capital. Obviously delay from the rig and now from the harbor were still going to pay a day rate of the rig sip there, a standby rate if you will. So we do have a little bit pressure on the cost. Eventually when we sanctioned the project, it was about $760 million Canadian. We think we’re probably at about $800 million range is hopefully where the project is going to end up. There has been a little bit of pressure as well as you know the strong Canadian dollar as well.

Amanda Fraser – AllNovaScotia.com

And I just have one last question, just given the current gas prices with us, the project have been approved back in 2007.

Mike Graham

Well, I think Randy will answer that one.

Randy Eresman

I would say that there is more caps.

Amanda Fraser – AllNovaScotia.com

Montney first.

Randy Eresman

It is in Montney [ph].

Amanda Fraser – AllNovaScotia.com

Could you just say that asset, could your raise your voice, could you just touch on that?

Randy Eresman

Hello. Sorry. I have a problem turning that mic on this morning. If the curve prices are – curve prices outlook had existed back in 2007; this project would have been more challenged there than approved.

Amanda Fraser – AllNovaScotia.com

Okay. Well. Thank you.

Operator

Your next question comes from the line of Dina O'Meara with Calgary Herald. Your line is open.

Dina O'Meara – Calgary Herald

Thank you. Just two questions, one do you expect Horn River to become commercial?

Randy Eresman

Mike.

Dina O'Meara – Calgary Herald

First question.

Mike Graham

Yeah, Dina. Mike Graham here. Like you say, we’re going to commercial development right now, if you will. We’re going to be producing – we’ll be average about 50 million cubic feet a day for 2010 and we should access 2011 at about 200 million cubic feet a day that to EnCana. So it is definitely commercial and all systems go on a Horn River. We have about 2.5 net really working there now and we drill as I say, may be 16 to about 20 wells per frac. Our drilling rig may be out there but as long as close to the year drilling one of these well pads and then we got to have to go in factures, stimulate that, that well pad which may take as, as much as six month if you were fracing around the clock, 24/7 now. And we do about two to two and half fracs each and every day. So this is probably close to the true gas manufacturing project as you can get.

Dina O'Meara – Calgary Herald

Do you have pipeline capacity to take it out to a plan?

Randy Eresman

Yeah. Right now, there is about 500 million cubic feet a day of excess capacity in the Fort Nelson, sectors Fort Nelson plan. So, we do plan to fill that up over the next few years and then by 2012, mid of 2012 – is where we would be in the 400 million cubic feet a day plan that EnCana is building, it will be on and then that's 200 million cubic feet a day will flow into TransCanada's Western mainline.

Dina O'Meara – Calgary Herald

Okay. What about pipeline? Getting the gas out of the Horn River?

Randy Eresman

Well. I can say we will bring in that initial 500 million cubic feet a day, ourselves and the Horn River producers. We will pipeline in it to sector for Nelson Gas, right into Spectra. Our well setup there, there is a lot of type in the area.

Dina O'Meara – Calgary Herald

Okay. Because I understand TransCanada had to lead the in service date of its Horn River mainline because of concerns by Horn River producers on commerciality to delay later the year.

Randy Eresman

Yeah. That's right. We have delayed. And like I say we are still planning on being up sort of mid-year 2012, may be September, 2012 at the latest.

Dina O'Meara – Calgary Herald

Wonderful. My next question has to do with Randy comments on – could you expand a little bit on land capturing new play in Western Canada that you mentioned?

Randy Eresman

Look we have spend some additional money in Canada and in several of our U.S. areas, looking for new perspective shale gas place and until we are ready to speak to about the specifics of them, we just need to keep to confidential usually when you are in land capture mode, when opportunities arise, it's not a wise thing to be making a lot of announcements.

Dina O’Meara – Calgary Herald

Well. Obviously everybody’s interest was piqued, when you spoke about a new play in Western Canada.

Randy Eresman

And it should be.

Dina O’Meara – Calgary Herald

Thank you so much. That's it from me

Randy Eresman

You’re welcome.

Operator

There are no further questions at this time. I will now turn the call back to Mr. Eresman. Please go ahead, sir.

Randy Eresman

Well. Thank you everyone for joining us today to review EnCana’s fourth quarter and year end results. Our conference call is now complete.

Operator

Thank you everyone for joining us today to review EnCana’s fourth quarter and year end 2009 results. Our conference call is now complete.

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.